In recent years, the development and deployment of inflow control devices (hereinafter “ICD”) has improved horizontal well production and reserve recovery in new and existing hydrocarbon wells. Indeed, ICD technology has increased reservoir drainage area, reduced water and/or gas coning occurrences, and increased overall hydrocarbon production rates. However, in longer, highly-deviated horizontal wells a continuing difficulty is the existence of non-uniform flow profiles along the length of the horizontal section, especially near well depletion. This problem typically arises as a result of non-uniform drawdown applied to the reservoir along the length of the horizontal section, but also can result from variations in reservoir pressure and the overall permeability of the hydrocarbon formation. Non-uniform flow profiles can lead to premature water or gas breakthrough, screen plugging and/or erosion in sand control wells, and may severely diminish well life and profitability. Likewise, in horizontal injection wells, the same phenomenon applied in reverse may result in uneven distribution of injection fluids that leave parts of the reservoir un-swept, thereby resulting in a loss of recoverable hydrocarbons.
Various intelligent completion methods have also been used to achieve uniform production/injection along the length of the horizontal wellbore. One method includes the use of sophisticated downhole flow control valves and pressure/temperature measurements that allow one to control drawdown and flow rate from various sections of the wellbore. However, this typically requires hydraulic and/or electric control lines that can limit the number of valves used and ultimately add to the overall cost of the completion. Other methods have tried installing pre-set, fixed nozzles configured to provide a pressure drop between the reservoir and the production tubular. Although each nozzle acts as a choke or valve that restricts the flow rate through the system, they are completely passive and have limited control on the actual flow rate through them and cannot adjust the choke size after the completion is in place.
Moreover, the pressure drop versus the flow rate will typically vary in proportion to the degree of reservoir depletion. For example, an ICD completion may initially be optimal for hydrocarbon production, but may subsequently fail to perform ideally as the reservoir pressure depletes. Current ICD designs fail to maintain a desired and consistent flow throughout the depletion of the reservoir, and often result in too high of an injection rate that result in unwanted gas/water coning.
FIG. 1 depicts a conventional well completion assembly configured to remove oil or some other hydrocarbon fluid from an underground reservoir 102. The wellbore 100 typically includes a cased, vertical section 104 joined at a “heel” 105 to an uncased, horizontal section 106. A production tubular 108 for transporting hydrocarbons, or other fluids, to the surface of the wellbore 100 is disposed within the cased wellbore section 104 and extends from the surface of the wellbore 100 through the heel 105 and to a “toe” 116. A packer 110 or other component for sealing off an annular area or wellbore annulus 112 around the production tubular 108 is typically used to isolate the horizontal section 106 therebelow. A completion assembly 114, such as a sand screen or perforated tubing, is normally attached to the production tubular 108 to allow the outflow and inflow of fluids therethrough.
During production, reservoir pressure variations and pressure drop inside the wellbore 100 may cause fluids to be produced or injected at non-uniform rates. This may be especially problematic in longer horizontal wells where pressure drop along the horizontal section 106 of the wellbore 100 causes maximum pressure drop at the heel 105 of the wellbore 100 (closest to the vertical or near vertical part 104) causing the heel 105 to produce or accept injection fluid at a higher rate than at the toe 116 of the wellbore 100 (farthest away from the vertical or near vertical departure point).
There is a need, therefore, for a flow control apparatus for use in a wellbore that compensates for dynamic changes and differences in fluid pressure along the length of the wellbore. There is also a need for a flow control apparatus that is self-regulating and that self-adjusts for changes in pressure differentials between the hydrocarbon formation and the production tubular.